This study presents an integrated, multi-scale laboratory workflow designed specifically for organic-rich shales using multistage solvent extraction. Applied to oil shales of the Bazhenov Formation of varying maturity and lithology, the key unconventional play in Western Siberia, it enables the construction of a robust, volumetric fluid saturation model. The workflow combines mineralogical characterization, conventional core testing, low-field nuclear magnetic resonance relaxometry, high-resolution X-ray computed microtomography, Rock-Eval pyrolysis, and sequential saturates, aromatics, resins, and asphaltenes fractionation following a three-stage solvent extraction protocol. The core analysis following three-step extraction provides new insights into the interplay between lithology, pore system architecture, and fluid distribution mechanisms within tight, organically heterogeneous media. Key findings highlight that conventional methods often underestimate producible hydrocarbons trapped in kerogen nanopores and asphaltene aggregates, necessitating revised nuclear magnetic resonance interpretation approaches. Mechanically induced porosity, varying with organic matter maturity, is identified and linked to hydrocarbon release and matrix deformation. Combining nuclear magnetic resonance and gas porosity measurements provides a rapid, accurate porosity estimation method with minimal sample alteration. Finally, a conceptual fluid physical model is proposed to better interpret nuclear magnetic resonance data and pore-scale fluid dynamics in similar oil shales. The refined methodology of express core assessment significantly improves industry conventional practices by enabling a more precise and physically meaningful quantification of in-situ fluid saturation, including differentiation between bound heavy hydrocarbons and mobile fractions. Beyond advancing the fundamental understanding of fluid saturation and storage capacity in unconventional systems, this framework supports improved reservoir characterization and modeling efforts.

Compared with conventional chemical enhanced oil recovery methods, micro/nanofluid-based emulsion systems offer several advantages, including improved mobility control, enhanced stability, and effective modification of interfacial properties, while requiring lower chemical dosage and exhibiting better tolerance to harsh reservoir conditions. This study systematically evaluated the potential of a novel nanofluid-based emulsion as an enhanced oil recovery agent, with emphasis on its rheological behavior, emulsion stability, and interfacial performance. Rheological measurements demonstrate that emulsion viscosity is strongly influenced by the water-to-oil ratio and mixing duration. Systems with low oil content exhibit only modest viscosity changes, whereas increasing oil fraction and mixing time result in pronounced viscosity enhancement, indicating the formation of structured emulsion networks. This viscosity growth contributes to improved emulsion stability, which is further supported by microscopic observations revealing complex multiphase structures. Interfacial characterization shows that the nanofluid-based emulsion effectively lowers the oil-water interfacial tension and induces a strong wettability shift toward water-wet conditions, both of which are favorable for enhanced oil displacement. Microfluidic displacement experiments provide pore-scale evidence that the combined effects of viscosity enhancement, improved emulsion stability, interfacial tension reduction, and wettability alteration lead to efficient mobilization of residual oil. Visual observations confirm in situ emulsion formation within the porous network and improved sweep behavior compared with conventional water injection. Overall, the results highlight the multifunctional role of nanofluid-based emulsions in stabilizing flow, enhancing sweep efficiency, and modifying interfacial dynamics, demonstrating their strong potential as an advanced chemical strategy for enhanced oil recovery applications.

Surfactant encapsulation presents a novel strategy for the targeted delivery of active molecules to oil reservoirs. This study investigates the interfacial tension, wettability alteration, static adsorption and oil displacement performance of two novel encapsulated surfactants, anionic alkyl ether carboxylate and non-ionic alkyl polyglucoside, in water-oil and water-oil-carbonate rock systems. A refined synthesis yielded silica carriers with dimensions appropriate for transport through carbonate reservoir pore networks, preventing pore blockage while enabling effective delivery. A synergism between the surfactants and silica nanoparticles, released upon carrier rupture, was confirmed. The cooperative action of silica nanoparticles and surfactant molecules, facilitated by multiple intermolecular forces, including hydrogen bonding, electrostatic, and hydrophobic, enhanced the efficiency of interfacial adsorption, leading to a significant reduction in interfacial tension compared to pure surfactant systems. Furthermore, silica nanoparticles accelerated the alteration in wettability towards a hydrophilic state via disjoining pressure and competitive adsorption on the carbonate surface. Consequently, the simultaneous enhancement of interfacial behavior and mitigation of static adsorption due to encapsulation translated into more efficient oil displacement compared to use of the pure surfactants. This work demonstrates that encapsulation not only reduces adsorption but also enhances interfacial performance and displacement efficiency, supporting its potential application in chemical enhanced oil recovery.